In recent years, methane and other gas-phase fuels have become more popular as a source of energy. One example of this phenomenon is the rapidly increasing use of gasification processes to generate power from energy sources such as coal or biomass. However, tighter governmental regulation have restricted the allowable levels of certain pollutants (e.g., sulfur species, acid gases, and other compounds of environmental concern) resulting from the use of these energy sources. Another problem associated with the presence of reduced sulfur gases (such as H2S, COS and CS2) in gas streams such as fuel gases, flue gases and waste gases arise in that these gases are corrosive, especially toward steel turbine blades. Consequently, the presence of reduced sulfur gases in the fuel gases used to power turbines results in severe blade corrosion. This has prompted fuel gas producers to develop more efficient methods to reduce pollutant emissions that comply with these increased standards.
Known methods of treating a gas stream to remove undesirable components include contacting the gas stream with a physical or chemical solvent. Examples of chemical solvents used for this purpose include amines such as methyldiethanolamine (MDEA) and diethanolamine (DEA). Often, the selectivity of the chemical solvents can be problematic. For example, while amines are capable of efficiently removing hydrogen sulfide (H2S) from gas streams, amines are generally not capable of absorbing other undesirable sulfur-containing compounds, such as, for example carbonyl sulfide (COS). As a result, additional process steps (e.g., COS hydrolysis) must be carried out before the gas stream can be used as fuel. In addition to removing H2S, most amines also remove carbon dioxide, which can place increased loads on subsequent waste gas processing facilities. Amine-based scrubbing processes also have technical problems such as the formation of heat stable salts, decomposition of amines, and are additionally equipment-intensive, thus requiring substantial capital investment.
Most processes for removing sulfur from a syngas stream utilizing chemical solvents require extensive cooling of the incoming gas stream to the range from 38° C. to below 0° C. Sour syngas usually leaves the gasification furnace at a temperature of at least 340° C., so the heat that must be removed in order to perform bulk sulfur removal equals 300° C. or more. This amount of heat removal requires large, expensive heat exchange equipment sometimes made with expensive, high alloy metallurgy. Additional equipment is required to recapture the removed heat by converting water into the large quantities of steam needed to remove absorbed contaminants from the amine solvent. Overall, the process is expensive to both deploy and operate.
Recently, improved techniques employing regenerable solid sorbents have been developed as a more efficient means for removing contaminants from syngas. Such regenerable sorbents are typically formed with a metal oxide component (e.g., ZnO) and a promoter metal component (e.g., Ni). When contacted with a sulfur-containing syngas at a temperature of approximately 375° C., the promoter metal and metal oxide components of the regenerable sorbent cooperate to remove sulfur from the hydrocarbon and store the removed sulfur on/in the sorbent via the conversion of the metal oxide component (e.g., ZnO) to a metal sulfide (e.g., ZnS). The resulting “sulfur-loaded” sorbent can then be regenerated by contacting the sulfur-loaded sorbent with an oxygen-containing regeneration stream.
During regeneration, the metal sulfide (e.g., ZnS) in the sulfur-loaded sorbent is returned to its original metal oxide form (e.g., ZnO) via reaction with the oxygen-containing regeneration stream. Further, during regeneration the promoter metal is oxidized to form an oxidized promoter metal component (e.g., NiO). After regeneration, the sorbent is once again reduced for further desulfurization by contacting it with the hydrogen-containing syngas stream. The oxidized promoter metal component is reduced by the hydrogen gas, thereby returning the sorbent to an optimum sulfur-removing state having a metal oxide component (e.g., ZnO) and a reduced-valence promoter component (e.g., Ni). Following reduction, the reduced sorbent is again competent to react with sulfur contaminants in the syngas.
Traditionally, solid sorbent compositions used in hydrocarbon desulfurization processes have been agglomerates utilized in fixed bed applications. Conventional fixed beds have the advantage of decreasing the attrition rate of the sorbent by immobilizing it, thus providing the longest sorbent lifespan. However, rapid clogging requires frequent regeneration of the fixed bed sorbent, and the required turn-over times are extensive.
Fluidized beds have three main advantages over fixed beds, in that, (1) they can more efficiently distribute the heat of reaction due to the constant mixing of the catalyst bed, (2) the catalyst that becomes inactive can be easily replaced in-situ, and (3) the catalyst has high surface area for maximizing bulk sulfur removal. In a typical fluid bed sorbent system utilizing continuous regeneration, a portion of the sulfur-loaded catalyst is constantly transferred to a separate regeneration vessel, then following regeneration, is returned to the main reactor. This system works well for sulfur contaminant removal from a liquid hydrocarbon feed. However, the relatively high sulfur level (1 to 2%) in a typical syngas feed quickly loads up the catalyst bed with sulfur, requiring a significantly increased rate of catalyst circulation to the regeneration chamber. Generally, attrition of solid particles is increased when solid particles are transported at high velocity. Thus, desulfurization units that employ dilute phase transport of the solid particles through and between vessels can cause significant attrition of the particles. When the solid particles employed in the desulfurization unit experience high levels of attrition, the solid particles must be replaced at frequent intervals, thereby increasing operating cost and downtime of the unit. While not wishing to be bound by theory, this increased rate of attrition may be in part due to increased pressure between adsorbent particles as the recirculating contaminant-removal apparatus is enlarged to the scale required for effective contaminant removal from a commercial syngas stream. In addition, increased sorbent circulation rates become cost-prohibitive at commercial scale due to requisite increases in regeneration reactor capacity (and consequent larger plot size) as well as reduced operational reliability. Finally, these systems are not conducive to maintaining a relatively constant temperature and pressure on the sorbent, thereby accelerating its rate of attrition.
Accordingly, a need exists for a more cost-efficient process for removing contaminants from a gas stream. The invention described herein provides a unique process for removing contaminants from a syngas stream, making it more energy-efficient, less complex, and consequently, less costly.